Natural Gas and LNG Price Outlook: What Drives Henry Hub Prices in 2026-2027

Natural gas heats homes, generates about 40% of U.S. electricity (EIA) and is a fast-growing U.S. export, shipped worldwide as liquefied natural gas (LNG). Its price is famously volatile. This guide explains what drives the U.S. benchmark, the Henry Hub price, using futures data from our market-data feed together with the latest official forecasts and statistics from the U.S. Energy Information Administration (EIA). Market figures refresh automatically. EIA figures are quoted from the publication dates given in the text and are updated when we revise the guide.

Key numbers

The official outlook: EIA forecasts for 2026–2027

The most widely cited public forecast for U.S. natural gas is the EIA’s monthly Short-Term Energy Outlook (STEO). The edition released on 6 October 2026 (forecast completed 1 October) contains these annual figures:

The EIA expects the 2027 average to be 32 cents (9%) lower than 2026. Most of that gap comes from one month: in January 2026, after winter storm Fern, the Henry Hub spot price averaged $7.72/MMBtu as heating demand jumped and the cold reduced supply. Excluding January, the agency forecasts an average of $3.09/MMBtu for February to December 2027, unchanged from the same months of 2026. Within 2027 it sees a seasonal low of $2.60/MMBtu in April and May and a year-end price of $3.90/MMBtu in December.

The reasoning behind the forecast is a balance between strong supply and growing demand. Production is expected to rise faster than domestic consumption, and the extra gas goes mainly to LNG export terminals. The EIA says ample inventories relative to the five-year average limit upward price pressure, and it expects storage to stay above that average in most months of the forecast. Its weather assumption matters too: the outlook assumes this winter will have about as many heating degree days as last winter and 1% fewer than the average of the previous five winters. A colder winter would draw down storage faster and push prices higher than forecast.

Henry Hub price history

To put the forecasts in context, the table below shows the yearly average of daily settlement prices for the front-month NYMEX Henry Hub futures contract, calculated from our data feed. The front-month contract tracks the spot price closely but not exactly.

Across all full years since 2001, the highest annual average was $9.02 in 2005 and the lowest was $2.13 in 2020. During the shale boom from 2010 to 2019, annual averages stayed between $2.53 and $4.38. The exceptions were driven by events: the 2022 energy crisis in Europe pulled U.S. prices up as LNG demand surged, and cold snaps such as the January 2026 storm produce short, extreme spikes.

Seasonality and the futures roll

Natural gas demand peaks in winter for heating and rises again in summer for air conditioning. Storage fills in the spring and autumn “shoulder” seasons and empties in winter. The table shows the typical level of each month’s average front-month price relative to the average for that year, using the median from 2010 to 2025 (100 = the year’s average).

The highest typical reading is in November (109) and the lowest in February (90). One detail often confuses readers: futures charts “roll” from one contract to the next. In late autumn the front month becomes a winter delivery contract, which usually trades at a premium, so a chart of the front-month price can jump at the roll even when the spot market has not changed. When comparing prices across months, check which delivery month each price refers to.

Storage: the weekly scorecard

Every Thursday the EIA publishes its Weekly Natural Gas Storage Report, which estimates how much working gas is held in underground storage in the Lower 48 states. Traders compare each week’s change with expectations and with the five-year average, and large surprises often move prices on the day.

In the report released on 22 October 2026, working gas stood at 3,644 Bcf for the week ending 16 October, after a net injection of 77 Bcf. That was 152 Bcf (4.0%) less than a year earlier and 35 Bcf (1.0%) above the five-year average of 3,609 Bcf. By region, the South Central region, the largest, was 3.4% below its five-year average, while the East, Midwest, Mountain and Pacific regions were above theirs.

In its October outlook, the EIA estimated that inventories would rise by 328 Bcf during October to about 3,850 Bcf at month-end, about 2% above the five-year average at the start of the heating season. The agency notes that injections can continue into mid-November, and that above-average inventories give a buffer against cold spells. Prolonged cold, however, could cause withdrawals larger than it expects.

LNG exports and global prices

LNG is the main reason U.S. gas demand is growing. The EIA reports that U.S. LNG exports averaged 17.4 Bcf/d in the first half of 2026, 23% more than a year earlier, the fastest growth since large-scale exports began in 2016. New capacity explains most of the increase. Plaquemines LNG is exporting at full capacity, and Corpus Christi Stage 3 is exporting from six of its seven trains. Together they add 4.0 Bcf/d of nominal export capacity when complete.

Golden Pass LNG became the ninth U.S. export terminal when it shipped its first cargo on 22 April 2026. The EIA says the project, owned by QatarEnergy (70%) and ExxonMobil (30%), has three trains of 0.7 Bcf/d nominal capacity each, for a total of 2.0 Bcf/d nominal (2.4 Bcf/d peak). Train 2 is expected in the second half of 2026 and Train 3 in the first half of 2027. In that 1 September analysis, based on its outlook at the time, the EIA estimated exports of 17.3 Bcf/d in the second half of 2026, rising to 18.7 Bcf/d in the first half of 2027.

Global events have kept international prices far above U.S. prices. According to the EIA, disruption to LNG shipments through the Strait of Hormuz in March 2026 cut off about 20% of global LNG supply, mostly from Qatar. Europe’s benchmark Title Transfer Facility (TTF) price averaged $14.74/MMBtu in the first half of 2026, up from $13.10 a year earlier, and the Japan-Korea Marker for Asian LNG averaged $15.56/MMBtu, a four-year high. U.S. exports to Asia more than doubled in volume. Even so, Henry Hub stayed at a fraction of those prices because U.S. exporters were already shipping close to their maximum capacity. Higher global prices raise exporters’ margins, but they cannot pull much more U.S. gas abroad until new liquefaction trains start up. For U.S. prices, the timing of terminal start-ups is therefore more important than the level of overseas prices.

How volatile is natural gas?

Natural gas is one of the most volatile major commodities. Based on daily front-month settlements, annualised volatility was 100% over the past year and 62% over the past month, compared with a long-run average of 61% since 2000. Swings of that size come from the physical market. Demand depends on the weather, supply cannot respond quickly, and storage capacity is finite, so small imbalances can produce large price moves. Leveraged products that track natural gas, including CFDs and some exchange-traded products, can lose value quickly, and products that roll futures contracts may not track the spot price over time. Our guide to managing market volatility covers position sizing.

Recent monthly averages of the front-month contract give a sense of the current trading pattern:

What to watch next

• Weather forecasts. Heating degree days from November to February are the biggest swing factor for winter prices and storage withdrawals.
• The Thursday storage report. Compare each week’s change with the five-year average and with consensus expectations.
• LNG start-ups and outages. New trains at Golden Pass and Corpus Christi Stage 3 add demand, while maintenance or outages at terminals reduce it.
• Production. The EIA expects dry gas production to keep rising, to 112.2 Bcf/d in 2026 and 116.1 Bcf/d in 2027. Any slowdown in drilling would tighten the balance.
• Global LNG prices and shipping routes. Disruptions such as the 2026 Hormuz shock raise demand for U.S. cargoes, though capacity limits the effect on Henry Hub.
• The next EIA outlook, due on 10 November 2026, which will update the forecasts above.

Methodology and limitations

Market figures use daily settlement prices for the continuous front-month NYMEX Henry Hub natural gas futures contract (NG=F) from the Yahoo Finance chart API, the provider behind our site ticker. Annual and monthly averages are simple averages of daily closes. Seasonality compares each month’s average with that calendar year’s average and takes the median across years. Volatility is the annualised standard deviation of daily log returns, using 252 trading days a year. Because the series rolls from one contract to the next, it is not the same as the EIA’s daily spot price. EIA forecasts and statistics are quoted from the releases listed below and are not adjusted by us. The market figures refresh at most every 12 hours. Forecasts are uncertain, and nothing here is a recommendation to trade.

Frequently asked questions

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Sources and method

• Price data: Yahoo Finance chart API, NYMEX Henry Hub natural gas front-month futures (NG=F) daily history since 30 Aug 2000, retrieved by Finbexo; data as of 28 Oct 2026
• U.S. EIA, Short-Term Energy Outlook, natural gas section (released 6 Oct 2026; next release 10 Nov 2026)
• U.S. EIA, Weekly Natural Gas Storage Report (week ending 16 Oct 2026, released 22 Oct 2026)
• U.S. EIA, Today in Energy: "U.S. LNG exports rose 23% in the first half of 2026 because of higher capacity" (1 Sep 2026)
• U.S. EIA, Today in Energy: "The 9th U.S. liquefied natural gas export terminal, Golden Pass, ships first cargo" (23 Apr 2026)
• Calculations: Finbexo (method described above)